In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections that are connected end-to-end so as to form a “drill string.” The bit is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating bit engages the earthen formation causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of cutting methods, thereby forming a borehole along a predetermined path toward a target zone.
Many different types of drill bits have been developed and found useful in drilling such boreholes. Two predominate types of drill bits are roller cone bits and fixed cutter (or rotary drag) bits. Most fixed cutter bit designs include a plurality of blades angularly spaced about the bit face. The blades project radially outward from the bit body and form flow channels therebetween. In addition, cutting elements are typically grouped and mounted on several blades in radially extending rows. The configuration or layout of the cutting elements on the blades may vary widely, depending on a number of factors such as the formation to be drilled.
The cutting elements disposed on the blades of a fixed cutter bit are typically formed of extremely hard materials. In a typical fixed cutter bit, each cutting element comprises an elongate and generally cylindrical tungsten carbide substrate that is received and secured in a pocket formed in the surface of one of the blades. The cutting elements typically include a hard cutting layer of polycrystalline diamond (PCD) or other superabrasive materials such as thermally stable diamond or polycrystalline cubic boron nitride. These cutting elements are designed to shear formations that range from soft to medium hard. For convenience, as used herein, reference to “PDC bit” or “PDC cutters” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive materials.
Referring to FIGS. 1 and 2, a conventional PDC bit 10 adapted for drilling through formations of rock to form a borehole is shown. PDC bit 10 generally includes a bit body 12, a shank 13, and a threaded connection or pin 14 for connecting the PDC bit 10 to a drill string (not shown) that is employed to rotate the bit in order to drill the borehole. Bit face 20 supports a cutting structure 15 and is formed on the end of the PDC bit 10 that is opposite pin end 16. PDC bit 10 further includes a central axis 11 about which PDC bit 10 rotates in the cutting direction represented by arrow 18.
Cutting structure 15 is provided on face 20 of PDC bit 10. Cutting structure 15 includes a plurality of angularly spaced-apart primary blades 31, 32, 33, and secondary blades 34, 35, 36, each of which extends from bit face 20. Primary blades 31, 32, 33 and secondary blades 34, 35, 36 extend generally radially along bit face 20 and then axially along a portion of the periphery of PDC bit 10. However, secondary blades 34, 35, 36 extend radially along bit face 20 from a position that is distal bit axis 11 toward the periphery of PDC bit 10. Thus, as used herein, “secondary blade” may be used to refer to a blade that begins at some distance from the bit axis and extends generally radially along the bit face to the periphery of the bit. Primary blades 31, 32, 33 and secondary blades 34, 35, 36 are separated by drilling fluid flow courses 19.
Referring still to FIGS. 1 and 2, each primary blade 31, 32, 33 includes blade tops 42 for mounting a plurality of cutting elements, and each secondary blade 34, 35, 36 includes blade tops 52 for mounting a plurality of cutting elements. In particular, cutting elements 40, each having a cutting face 44, are mounted in pockets formed in blade tops 42, 52 of each primary blade 31, 32, 33 and each secondary blade 34, 35, 36, respectively. Cutting elements 40 are arranged adjacent one another in a radially extending row proximal the leading edge of each primary blade 31, 32, 33 and each secondary blade 34, 35, 36. Each cutting face 44 has an outermost cutting tip 44a furthest from blade tops 42, 52 to which cutting element 40 is mounted.
Referring now to FIG. 3, a profile of PDC bit 10 is shown as it would appear with each of the blades (e.g., primary blades 31, 32, 33 and secondary blades 34, 35, 36) and cutting faces 44 of each of the cutting elements 40 rotated into a single rotated profile. In rotated profile view, blade tops 42, 52 of each of the blades 31-36 of PDC bit 10 form and define a combined or composite blade profile 39 that extends radially from bit axis 11 to outer radius 23 of PDC bit 10. Thus, as used herein, the phrase “composite blade profile” refers to the profile, extending from the bit axis to the outer radius of the bit, formed by the blade tops of each of the blades of a bit rotated into a single rotated profile (i.e., in rotated profile view).
Conventional composite blade profile 39 (most clearly shown in the right half of PDC bit 10 in FIG. 3) may generally be divided into three regions conventionally labeled cone region 24, shoulder region 25, and gage region 26. Cone region 24 comprises the radially innermost region of PDC bit 10 and composite blade profile 39 extending generally from bit axis 11 to shoulder region 25. As shown in FIG. 3, in most conventional fixed cutter bits, cone region 24 is generally concave. Adjacent cone region 24 is shoulder (or the upturned curve) region 25. In most conventional fixed cutter bits, shoulder region 25 is generally convex. Moving radially outward, adjacent shoulder region 25 is the gage region 26 which extends parallel to bit axis 11 at the outer radial periphery of composite blade profile 39. Thus, composite blade profile 39 of conventional PDC bit 10 includes one concave region—cone region 24, and one convex region—shoulder region 25.
The axially lowermost point of convex shoulder region 25 and composite blade profile 39 defines a blade profile nose 27. At blade profile nose 27, the slope of a tangent line 27a to convex shoulder region 25 and composite blade profile 39 is zero. Thus, as used herein, the term “blade profile nose” refers to the point along a convex region of a composite blade profile of a bit in rotated profile view at which the slope of a tangent to the composite blade profile is zero. For most conventional fixed cutter bits (e.g., PDC bit 10), the composite blade profile includes a single convex shoulder region (e.g., convex shoulder region 25), and a single blade profile nose (e.g., nose 27). As shown in FIGS. 1-3, cutting elements 40 are arranged in rows along blades 31-36 and are positioned along the bit face 20 in the regions previously described as cone region 24, shoulder region 25 and gage region 26 of composite blade profile 39. In particular, cutting elements 40 are mounted on blades 31-36 in predetermined radially-spaced positions relative to the central axis 11 of the PDC bit 10.
For drilling harder formations, the mechanism for drilling changes from shearing to abrasion. For abrasive drilling, bits having fixed, abrasive elements are conventionally used. While PDC bits are known to be effective for drilling some formations, they have been found to be less effective for hard, very abrasive formations such as sandstone. For these hard formations, cutting structures that comprise particulate diamond, or diamond grit, impregnated in a supporting matrix are effective. In the discussion that follows, components of this type are referred to as “diamond impregnated.”
Diamond impregnated drill bits are commonly used for boring holes in very hard or abrasive rock formations. The cutting face of such bits contains natural or synthetic diamonds distributed within a supporting material (e.g., metal-matrix composites) to form an abrasive layer. During operation of the drill bit, diamonds within the abrasive layer are gradually exposed as the supporting material is worn away. The continuous exposure of new diamonds by wear of the supporting material on the cutting face is the fundamental functional principle for impregnated drill bits.
An example of a prior art diamond impregnated drill bit is shown in FIG. 4. The impregnated bit 70 includes a bit body 72 and a plurality of ribs 74 that are formed in the bit body 72. Ribs 74 may extend from a center of the bit body radially outward to the outer diameter of the bit body 72, and then axially downward, to define the diameter (or gage) of the impregnated bit 70. The ribs 74 are separated by channels 76 that enable drilling fluid to flow between and both clean and cool the ribs 74. The ribs 74 are typically arranged in groups 79 where a gap 78 between groups 79 is typically formed by removing or omitting at least a portion of a rib 74. The gaps 78, which may be referred to as “fluid courses,” are positioned to provide additional flow channels for drilling fluid and to provide a passage for formation cuttings to travel past the drill bit 70 toward the surface of a wellbore (not shown).
Referring now to FIG. 5, an example of a prior art impregnated bit 80 in accordance with U.S. Pat. No. 6,394,202, which is assigned to the assignee of the present invention and is hereby incorporated by reference, is shown. In FIG. 5, the impregnated bit 80 comprises a shank 82 and a crown 84. Shank 82 is typically formed of steel and includes a threaded pin 86 for attachment to a drill string. Crown 84 has a cutting face 88 and outer side surface 89. According to one or more embodiments, crown 84 is formed by infiltrating a mass of tungsten-carbide powder impregnated with synthetic or natural diamond.
Crown 84 may include various surface features, such as raised ribs 74. Preferably, formers are included during the manufacturing process so that the infiltrated, diamond-impregnated crown includes a plurality of holes or sockets 85 that are sized and shaped to receive a corresponding plurality of diamond-impregnated inserts 83. Once crown 84 is formed, inserts 83 are mounted in the sockets 85 and affixed by any suitable method, such as brazing, adhesive, mechanical means such as interference fit, or the like. As shown in FIG. 5, the sockets 85 can be substantially perpendicular to the surface of the crown 84. As shown in FIG. 5, sockets 85 can each be substantially perpendicular to the surface of the crown 84. In this embodiment, the sockets 85 are inclined such that inserts 83 are oriented substantially in the direction of rotation of the bit, so as to enhance cutting.
Referring now to FIG. 6, an example of a cross-sectional view of a rib of a prior art impregnated drill bit is shown. The rib 74 has a profile 90 defining its general shape/geometry that may be divided into various segments: a cone region 92 (recessed central area), a nose region 94 (leading cutting edge of profile), a shoulder region 96 (beginning of outside diameter of bit), transition region 98 (transition between shoulder and vertical gage), and a gage region 99 (vertical region defining outer diameter of bit). The primary cutting portion of the rib 74 includes cone region 92, nose region 94, and shoulder region 96, whereas gage region 99 is primarily responsible for maintaining the hole size.
Without regard to the type of bit, the cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit is changed in order to reach the targeted formation. This is the case because each time the bit is changed, the entire drill string, which may be miles long, is retrieved from the borehole section by section. Once the drill string has been retrieved and the new bit installed, the bit is lowered to the bottom of the borehole on the drill string, which again is constructed section by section. This process, known as a “trip” of the drill string, involves considerable time, effort, and expense. Accordingly, it may be desirable to employ drill bits that will drill faster and longer and that are usable over a wider range of differing formation hardnesses and applications.
The length of time that a drill bit may be employed before it is changed depends upon its rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP. Specifically, ROP is the rate that a drill bit penetrates a given subterranean formation. ROP is typically measured in feet per hour. There is an ongoing effort to optimize the design of drill bits to more rapidly drill specific formations so as to reduce drilling costs, which are affected by ROP.
Once a desired formation is reached in the borehole, a core sample of the formation may be extracted for analysis. Conventionally, a hollow coring bit is employed to extract a core sample from the formation. Once the core sample has been transported from the borehole to the surface, the sample may be used to analyze and test, for example, permeability, porosity, composition, or other geological properties of the formation.
Regardless of the type of drill bit employed to drill the formation, conventional coring methods involve retrieval of the drill string from the borehole, replacement of the drill bit with a coring bit, and lowering of the coring bit into the borehole on the drill string in order to retrieve a core sample, which is then taken along the path of the borehole to reach the surface for analysis. That is, conventional coring methods involve tripping the drill string, and thus considerable time, effort, and expense.